Absorbent for selective removal of hydrogen sulfide from a fluid stream

ABSTRACT

An absorbent for selective removal of hydrogen sulfide from a fluid stream comprises an aqueous solution of a) a tertiary amine, b) a sterically hindered secondary amine of the general formula (I) 
                         
in which R 1  and R 2  are each independently selected from C 1-4 -alkyl and C 1-4 -hydroxyalkyl; R 3 , R 4 , R 5  and R 6  are each independently selected from hydrogen, C 1-4 -alkyl and C 1-4 -hydroxyalkyl, with the proviso that at least one R 4  and/or R 5  radical on the carbon atom bonded directly to the nitrogen atom is C 1-4 -alkyl or C 1-4 -hydroxyalkyl when R 3  is hydrogen; x and y are integers from 2 to 4 and z is an integer from 1 to 4; where the molar ratio of b) to a) is in the range from 0.05 to 1.0, and c) an acid in an amount, calculated as neutralization equivalent relative to the protonatable nitrogen atoms in a) and b), of 0.05 to 15.0%. One preferred amine of the formula I is 2-(2-tert-butylaminoethoxy)ethanol. The absorbent allows a defined H 2 S selectivity to be set at pressures of the kind typical in natural gas processing.

The present invention relates to an absorbent for removing acidic gasesfrom fluid streams, especially for selective removal of hydrogensulfide, and to a process for removing acidic gases from a fluid stream,especially for selective removal of hydrogen sulfide over carbondioxide.

The removal of acid gases, for example CO₂, H₂S, SO₂, CS₂, HCN, COS ormercaptans, from fluid streams such as natural gas, refinery gas orsynthesis gas is important for various reasons. The content of sulfurcompounds in natural gas has to be reduced directly at the natural gassource through suitable treatment measures, since the sulfur compoundsform acids having corrosive action in the water frequently entrained bythe natural gas. For the transport of the natural gas in a pipeline orfurther processing in a natural gas liquefaction plant (LNG=liquefiednatural gas), given limits for the sulfur-containing impuritiestherefore have to be observed. In addition, numerous sulfur compoundsare malodorous and toxic even at low concentrations.

One of the reasons carbon dioxide must be removed from natural gas isthat a high concentration of CO₂ reduces the calorific value of the gas.Moreover, CO₂ in conjunction with moisture, which is frequentlyentrained in the fluid streams, can lead to corrosion in pipes andvalves. If natural gas is liquefied for transport as liquefied naturalgas (LNG), the CO₂ must be largely removed beforehand. At thetemperature of the liquefied natural gas (around −162° C.), the CO₂would resublimate and would damage plant components. Too low aconcentration of CO₂, on the other hand, can likewise be undesirable, inconnection, for example, with feeding into the natural gas network,since the calorific value of the gas can be too high as a result.

Acid gases are removed by using scrubbing operations with aqueoussolutions of inorganic or organic bases. When acid gases are dissolvedin the absorbent, ions form with the bases. The absorption medium can beregenerated by decompression to a lower pressure and/or by stripping, inwhich case the ionic species react in reverse to form acid gases and/orare stripped away by means of steam. After the regeneration process, theabsorbent can be reused.

A process in which all acid gases, especially CO₂ and H₂S, are verysubstantially removed is referred to as “total absorption”. Inparticular cases, in contrast, it may be desirable to preferentiallyabsorb H₂S over CO₂, for example in order to obtain a calorificvalue-optimized CO₂/H₂S ratio for a downstream Claus plant. In thiscase, reference is made to “selective scrubbing”. An unfavorable CO₂/H₂Sratio can impair the performance and efficiency of the Claus plantthrough formation of COS/CS₂ and coking of the Claus catalyst or throughtoo low a calorific value.

Highly sterically hindered secondary amines, such as2-(2-tert-butylaminoethoxy)ethanol, and tertiary amines, such asmethyldiethanolamine (MDEA), exhibit kinetic selectivity for H₂S overCO₂. These amines do not react directly with CO₂; instead, CO₂ isreacted in a slow reaction with the amine and with water to givebicarbonate—in contrast, H₂S reads immediately in aqueous aminesolutions. Such amines are therefore especially suitable for selectiveremoval of H₂S from gas mixtures comprising CO₂ and H₂S.

The selective removal of hydrogen sulfide is frequently employed in thecase of fluid streams having low partial acid gas pressures, for examplein tail gas, or in the case of acid gas enrichment (AGE), for examplefor enrichment of H₂S prior to the Claus process.

For instance, U.S. Pat. No. 4,471,138 showed that highly stericallyhindered secondary amines such as 2-(2-tert-butylaminoethoxy)ethanol,even in combination with further amines such as methyldiethanolamine,have a much higher H₂S selectivity than methyldiethanolamine. Thiseffect was confirmed, inter alia, by Lu et al. in Separation andPurification Technology, 2006, 52, 209-217. EP 0 084 943 discloses theuse of tertiary alkanolamines and highly sterically hindered secondaryand tertiary alkanolamines in absorption solutions for selective removalof hydrogen sulfide over carbon dioxide from gas streams.

EP 134 948 describes an absorbent comprising an alkaline material and anacid having a pK_(a) of 6 or less. Preferred acids are phosphoric acid,formic acid or hydrochloric acid. The addition of acid is especiallysaid to make the stripping of H₂S-comprising acidic gases moreefficient.

U.S. Pat. No. 4,618,481 discloses the removal of hydrogen sulfide fromfluid streams with an absorption solution comprising a highly stericallyhindered amine and an amine salt. U.S. Pat. No. 4,892,674 discloses theremoval of hydrogen sulfide from fluid streams with an absorptionsolution comprising an amine and a highly sterically hindered amino saltand/or a sterically hindered amino acid. One teaching of the document,with reference to FIG. 3, is that the H₂S selectivity of MDEA can beincreased by addition of 2-(2-tert-butylaminoethoxy)ethanol sulfate.

In the case of natural gas treatment for pipeline gas too, selectiveremoval of H₂S over CO₂ may be desirable. The absorption step in naturalgas treatment is typically effected at high pressures of about 20 to 130bar (absolute). In general, distinctly higher partial acid gas pressuresare present compared, for example, to tail gas treatment, namely, forexample, at least 0.2 bar for H₂S and at least 1 bar for CO₂.

A use example within this pressure range is disclosed in U.S. Pat. No.4,101,633, in which a process for removing carbon dioxide from gasmixtures is described. An absorbent comprising at least 50% of asterically hindered alkanolamine and at least 10% of a tertiary aminoalcohol is used. U.S. Pat. No. 4,094,957 discloses a use example withinthis pressure range, in which a process for removing carbon dioxide froma gas mixture is described. An absorbent comprising a basic alkali metalsalt or hydroxide, at least one sterically hindered amine and a C₄₋₈amino acid is used.

In many cases, the aim in natural gas treatment is simultaneous removalof H₂S and CO₂, wherein given H₂S limits have to be observed butcomplete removal of CO₂ is unnecessary. The specification typical ofpipeline gas requires acid gas removal to about 1.5% to 3.5% by volumeof CO₂ and less than 4 ppmv of H₂S. In these cases, maximum H₂Sselectivity is undesirable.

US 2013/0243676 describes a process for absorption of H₂S and CO₂ from agas mixture with an absorbent comprising a highly sterically hinderedtertiary etheramine triethylene glycol alcohol or derivatives thereofand a liquid amine.

It is an object of the invention to specify an absorbent and a processthat allows the setting of a defined H₂S selectivity at pressures of thekind typically found in the processing of natural gas for pipeline gas.The regeneration energy required is not to be substantially increasedrelative to H₂S-selective absorbents.

The object is achieved by an absorbent for selective removal of hydrogensulfide from a fluid stream, comprising an aqueous solution whichcomprises:

-   a) a tertiary amine;-   b) a sterically hindered secondary amine of the general formula (I)

-   -   in which R₁ and R₂ are each independently selected from        C₁₋₄-alkyl and C₁₋₄-hydroxyalkyl; R₃, R₄, R₅ and R₆ are each        independently selected from hydrogen, C₁₋₄-alkyl and        C₁₋₄-hydroxyalkyl, with the proviso that at least one R₄ and/or        R₅ radical on the carbon atom bonded directly to the nitrogen        atom is C₁₋₄-alkyl or C₁₋₄-hydroxyalkyl when R₃ is hydrogen; x        and y are integers from 2 to 4 and z is an integer from 1 to 4;        where the molar ratio of b) to a) is in the range from 0.05 to        1.0, and

-   c) an acid in an amount, calculated as neutralization equivalent    relative to the protonatable nitrogen atoms in a) and b), of 0.05 to    15.0%.

Protonation equilibria form between the acid and the amines according toa) and/or b). The position of the equilibria is temperature-dependent,and the equilibrium is shifted at higher temperatures toward the freeoxonium ion and/or the amine salt having the lower enthalpy ofprotonation. Amines of the general formula (I) exhibit a particularlymarked temperature dependence of the pK_(a). The result of this is that,at relatively low temperatures as exist in the absorption step, thehigher pH promotes efficient acid gas absorption, whereas, at relativelyhigh temperatures as exist in the desorption step, the lower pH supportsthe release of the absorbed acid gases. It is expected that a highdifference in the pH values of the absorbent between the absorption anddesorption temperature will cause a lower regeneration energy.

By varying the molar ratio of b) to a) within the stated limits it ispossible to adapt the H₂S selectivity to the particular requirements.Despite reduced H₂S selectivity, the regeneration energy is the same asor less than that of an H₂S-selective absorbent.

In general, the total concentration of a) and b) in the aqueous solutionis 10% to 60% by weight, preferably 20% to 50% by weight, morepreferably 30% to 50% by weight.

The molar ratio of b) to a) is in the range from 0.05 to 1.0, preferably0.1 to 0.9, in particular 0.3 to 0.7.

The aqueous solution comprises acid in an amount, calculated asneutralization equivalent relative to the protonatable nitrogen atoms ina) and b), of 0.05 to 15.0%, preferably 1.0 to 9.0%, more preferably 2.5to 6.5%.

A “neutralization equivalent” means the notional fraction of an acidmolecule which is able, in the neutralization reaction in aqueoussolution, to give up a proton. For example, one molecule of H₂SO₄corresponds to two neutralization equivalents, one molecule of H₃PO₄ tothree neutralization equivalents.

The term “protonatable nitrogen atoms” refers to the sum total ofnitrogen atoms present in the amines as per a) and b) that can beprotonated in aqueous solution. Generally speaking, these are nitrogenatoms of amino groups.

It has been found that the absorbent is subject to stability limitswithin the above-defined limits of the composition. Higher amounts ofacid than specified or a greater molar ratio of b) to a) lead to adeterioration in stability and accelerated breakdown of the absorbent atelevated temperature.

The inventive absorbent comprises, as component a), at least onetertiary amine. A “tertiary amine” is understood to mean compoundshaving at least one tertiary amino group. The tertiary amine preferablycomprises exclusively tertiary amino groups, meaning that it does notcomprise any primary or secondary amino groups alongside at least onetertiary amino group. The tertiary amine is preferably a monoamine. Thetertiary amine preferably does not have any acidic groups such as, inparticular, phosphonic acid, sulfonic acid and/or carboxylic acidgroups.

The suitable tertiary amines a) especially include:

1. Tertiary alkanolamines such as

bis(2-hydroxyethyl)methylamine (methyldiethanolamine, MDEA),tris(2-hydroxyethyl)amine (triethanolamine, TEA), tributanolamine,2-diethylaminoethanol (diethylethanolamine, DEEA),2-dimethylaminoethanol (dimethylethanolamine, DMEA),3-dimethylamino-1-propanol (N,N-dimethylpropanolamine),3-diethylamino-1-propanol, 2-diisopropylaminoethanol (DIEA),N,N-bis(2-hydroxypropyl)methylamine (methyldiisopropanolamine, MDIPA);2. Tertiary amino ethers such as3-methoxypropyldimethylamine;3. Tertiary polyamines, for example bis-tertiary diamines such asN,N,N′,N′-tetramethylethylenediamine,N,N-diethyl-N′,N′-dimethylethylenediamine,N,N,N′,N′-tetramethylethylenediamine,N,N,N′,N′-tetramethyl-1,3-propanediamine (TMPDA),N,N,N′,N′-tetraethyl-1,3-propanediamine (TEPDA),N,N-dimethyl-N′,N′-diethylethylenediamine (DMDEEDA),1-dimethylamino-2-dimethylaminoethoxyethane (bis[2-(dimethylamino)ethyl]ether);and mixtures thereof.

Tertiary alkanolamines, i.e. amines having at least one hydroxyalkylgroup bonded to the nitrogen atom, are generally preferred. Particularpreference is given to methyldiethanolamine (MDEA).

The absorbent of the invention comprises a sterically hindered secondaryamine of the formula (I). In the formula (I), R₁, R₂ and R₃ arepreferably methyl or ethyl; R₄, R₅ and R₆ are preferably methyl orhydrogen. Suitable sterically hindered secondary amines includesecondary amino ether alkanols, such as the compounds disclosed in U.S.Pat. No. 4,471,128, for example. The secondary amino ether alkanolscomprise, for example, 2-(2-tert-butylaminoethoxy)ethanol (TBAEE),2-(2-tert-butylamino)propoxyethanol, tert-amylaminoethoxyethanol,(1-methyl-1-ethylpropylamino)ethoxyethanol,2-2-(2-isopropylamino)propoxyethanol, and mixtures thereof. Preferenceis given to 2-(2-tert-butylaminoethoxy)ethanol (TBAEE).

Amines of the formula (I) comprise those which are referred to in theprior art as highly sterically hindered amines and have a stericparameter (Taft constant) E_(S) of more than 1.75.

The inventive absorbent comprises at least one acid. The acid issuitably selected from protic acids (Brønsted acids), preferably havinga pK_(a) of less than 6, especially less than 5. In the case of acidshaving more than one dissociation stage and accordingly more than onepK_(a), this requirement is met where one of the pK_(a) values is withinthe range specified.

The acid is selected from organic and inorganic acids. Suitable organicacids comprise, for example, phosphonic acids, sulfonic acids,carboxylic acids and amino acids. In particular embodiments, the acid isa polybasic acid.

Suitable acids are, for example,

mineral acids such as hydrochloric acid, sulfuric acid, amidosulfuricacid, phosphoric acid, partial esters of phosphoric acid, for examplemono- and dialkyl phosphates and mono- and diaryl phosphates such astridecyl phosphate, dibutyl phosphate, diphenyl phosphate andbis(2-ethylhexyl) phosphate; boric acid;carboxylic acids, for example saturated aliphatic monocarboxylic acidssuch as formic acid, acetic acid, propionic acid, butyric acid,isobutyric acid, valeric acid, isovaleric acid, pivalic acid, caproicacid, n-heptanoic acid, caprylic acid, 2-ethyihexanoic acid, pelargonicacid, caproic acid, neodecanoic acid, undecanoic acid, lauric acid,tridecanoic acid, myristic acid, pentadecanoic acid, palmitic acid,margaric acid, stearic acid, isostearic acid, arachic acid, behenicacid; saturated aliphatic polycarboxylic acids such as oxalic acid,malonic acid, succinic acid, glutaric acid, adipic acid, pimelic acid,suberic acid, azelaic acid, sebacic acid, dodecanedioic acid;cycloaliphatic mono- and polycarboxylic acids such ascyclohexanecarboxylic acid, hexahydrophthalic acid, tetrahydrophthalicacid, resin acids, naphthenic acids; aliphatic hydroxycarboxylic acidssuch as glycolic acid, lactic acid, mandelic acid, hydroxybutyric acid,tartaric acid, malic acid, citric acid; halogenated aliphatic carboxylicacids such as trichloroacetic acid or 2-chloropropionic acid; aromaticmono- and polycarboxylic acids such as benzoic acid, salicylic acid,gallic acid, the positionally isomeric toluic acids, methoxybenzoicacids, chlorobenzoic acids, nitrobenzolc acids, phthalic acid,terephthalic acid, isophthalic acid; technical carboxylic acid mixtures,for example Versatic acids;sulfonic acids such as methylsulfonic acid, butylsulfonic acid,3-hydroxypropylsulfonic acid, sulfoacetic acid, benzenesulfonic acid,p-toluenesulfonic acid, p-xylenesulfonic acid, 4-dodecylbenzenesulfonicacid, 1-naphthalenesulfonic acid, dinonylnaphthalenesulfonic acid anddinonylnaphthalenedisulfonic acid, trifluoromethyl- ornonafluoro-n-butylsulfonic acid, camphorsulfonic acid,2-(4-(2-hydroxyethyl)-1-piperazinyl)ethanesulfonic acid (HEPES);organic phosphonic acids, for example phosphonic acids of the formula IIR₃₁—PO₃H  (VIII)in which R₃₁ is C₁₋₁₈-alkyl optionally substituted by up to foursubstituents independently selected from carboxyl, carboxamido, hydroxyland amino.

These include alkylphosphonic acids such as methylphosphonic acid,propylphosphonic acid, 2-methylpropylphosphonic acid, t-butylphosphonicacid, n-butylphosphonic acid, 2,3-dimethylbutylphosphonic acid,octylphosphonic acid; hydroxyalkylphosphonic acids such ashydroxymethylphosphonic acid, 1-hydroxyethylphosphonic acid,2-hydroxyethylphosphonic acid; arylphosphonic acids such asphenylphosphonic acid, tolylphosphonic acid, xylylphosphonic acid,aminoalkylphosphonic acids such as aminomethylphosphonic acid,1-aminoethylphosphonic acid, 1-dimethylaminoethylphosphonic acid,2-aminoethylphosphonic acid, 2-(N-methylamino)ethylphosphonic acid,3-aminopropylphosphonic acid, 2-aminopropylphosphonic acid,1-aminopropylphosphonic acid, 1-aminopropyl-2-chloropropylphosphonicacid, 2-aminobutylphosphonic acid, 3-aminobutylphosphonic acid,1-aminobutylphosphonic acid, 4-aminobutylphosphonic acid,2-aminopentylphosphonic acid, 5-aminopentylphosphonic acid,2-aminohexylphosphonic acid, 5-aminohexylphosphonic acid,2-aminooctylphosphonic acid, 1-aminooctylphosphonic acid,1-aminobutylphosphonic acid; amidoalkylphosphonic acids such as3-hydroxymethylamino-3-oxopropylphosphonic acid; and phosphonocarboxylicacids such as 2-hydroxyphosphonoacetic acid and2-phosphonobutane-1,2,4-tricarboxylic acid;

phosphonic acids of the formula III

in which R₃₂ is H or C₁₋₆-alkyl, Q is H, OH or NY₂ and Y is H orCH₂PO₃H₂, such as 1-hydroxyethane-1,1-diphosphonic acid;phosphonic acids of the formula IV

in which Z is C₂₋₆-alkylene, cycloalkanedlyl, phenylene, orC₂₋₆-alkylene interrupted by cycloalkanedlyl or phenylene, Y is CH₂PO₃H₂and m is 0 to 4, such as ethylenediaminetetra(methylenephosphonic acid),diethylenetriaminepenta(methylenephosphonic acid) andbis(hexamethylene)triaminepenta(methylenephosphonic acid);phosphonic acids of the formula VR₃₃—NY₂  (V)in which R₃₃ is C₁₋₆-alkyl, C₂₋₆-hydroxyalkyl or Y, and Y is CH₂PO₃H₂,such as nitrilotris(methylenephosphonic acid) and2-hydroxyethyliminobis(methylenephosphonic acid);tertiary aminocarboxylic acids, i.e. aminocarboxylic acids havingtertiary amino groups, and N-sec-alkylaminocarboxylic acids andN-tert-alkylamino-carboxylic acids, i.e. amino acids having or aminogroups and having at least one secondary or tertiary carbon atomimmediately adjacent to the amino group, such asα-amino acids having tertiary amino groups or amino groups having atleast one secondary or tertiary carbon atom immediately adjacent to theamino group, such as N,N-dimethyglycine (dimethylaminoacetic acid),N,N-diethylglycine, alanine (2-aminopropionic acid), N-methylalanine(2-(methylamino)propionic acid), N,N-dimethylalanine, N-ethylalanine,2-methylalanine (2-aminoisobutyric acid), leucine(2-amino-4-methylpentan-1-oic acid), N-methylleucine,N,N-dimethylleucine, isoleucine (1-amino-2-methylpentanoic acid),N-methylisoleucine, N,N-dimethylisoleucine, valine (2-aminoisovalericacid), α-methylvaline (2-amino-2-methylisovaleric acid), N-methylvaline(2-methylaminoisovaleric acid), N,N-dimethylvaline, proline(pyrrolidine-2-carboxylic acid), N-methylproline, N-methylserine,N,N-dimethylserine, 2-(methylamino)isobutyric acid,piperidine-2-carboxylic acid, N-methylpiperidine-2-carboxylic acid,β-aminocarboxylic acids having tertiary amino groups or amino groupshaving at least one secondary or tertiary carbon atom Immediatelyadjacent to the amino group, such as 3-dimethylaminopropionic acid,N-methyliminodipropionic acid, N-methylpiperidine-3-carboxylic acid,γ-amino acids having tertiary amino groups or amino groups having atleast one secondary or tertiary carbon atom immediately adjacent to theamino group, such as 4-dimethylaminobutyric acid,or aminocarboxylic acids having tertiary amino groups or amino groupshaving at least one secondary or tertiary carbon atom immediatelyadjacent to the amino group, such as N-methylpiperidine-4-carboxylicacid.

Among the inorganic acids, preference is given to phosphoric acid andsulfuric acid.

Among the carboxylic acids, preference is given to formic acid, aceticacid, benzoic acid, succinic acid and adipic acid.

Among the sulfonic acids, preference is given to methanesulfonic acid,p-toluenesulfonic acid and2-(4-(2-hydroxyethyl)-1-piperazinyl)ethanesulfonic acid (HEPES).

Among the phosphonic acids, preference is given to2-hydroxyphosphonoacetic acid, 2-phosphonobutane-1,2,4-tricarboxylicacid, 1-hydroxyethane-1,1-diphosphonic acid,ethylenediaminetetra(methylenephosphonic acid),diethylenetriaminepenta(methylenephosphonic acid),bis(hexamethylene)triaminepenta(methylenephosphonic acid) (HDTMP) andnitrilotris(methylenephosphonic acid), among which1-hydroxyethane-1,1-diphosphonic acid is particularly preferred.

Among the aminocarboxylic acids having tertiary amino groups or aminogroups having at least one secondary or tertiary carbon atom immediatelyadjacent to the amino group, preference is given to N,N-dimethylglycineand N-methylalanine.

More preferably, the acid is an inorganic acid.

The absorbent may also comprise additives such as corrosion inhibitors,enzymes, etc. In general, the amount of such additives is in the rangefrom about 0.01% to 3% by weight of the absorbent.

Preferably, the absorbent does not comprise any sterically unhinderedprimary or secondary amine. Compounds of this kind act as strongpromoters of CO₂ absorption.

As a result of their presence, the H₂S selectivity of the absorbent canbe lost.

A sterically unhindered primary or secondary amine is understood to meancompounds having primary or secondary amino groups to which onlyhydrogen atoms or primary carbon atoms are bonded.

The invention also relates to a process for the removal of acidic gasesfrom a fluid stream, in which the fluid stream is contacted with theabsorbent defined above.

In general, the laden absorbent is regenerated by

a) heating,

b) decompression,

c) stripping with an inert fluid

or a combination of two or all of these measures.

The process according to the invention is suitable for treatment of allkinds of fluids. Fluids are firstly gases such as natural gas, synthesisgas, coke oven gas, cracking gas, coal gasification gas, cycle gas,landfill gases and combustion gases, and secondly fluids that areessentially immiscible with the absorbent, such as LPG (liquefiedpetroleum gas) or NGL (natural gas liquids). The process according tothe invention is particularly suitable for treatment ofhydrocarbonaceous fluid streams. The hydrocarbons present are, forexample, aliphatic hydrocarbons such as C₁₋₄ hydrocarbons such asmethane, unsaturated hydrocarbons such as ethylene or propylene, oraromatic hydrocarbons such as benzene, toluene or xylene.

The absorbent or process according to the invention is suitable forremoval of CO₂ and H₂S. As well as carbon dioxide and hydrogen sulfide,it is possible for other acidic gases to be present in the fluid stream,such as COS and mercaptans. In addition, it is also possible to removeSO₃, SO₂, CS₂ and HCN.

The process according to the invention is suitable for selective removalof hydrogen sulfide over CO₂. In the present context, “selectivity forhydrogen sulfide” is understood to mean the value of the followingquotient:

$\frac{\frac{{y\left( {H_{2}S} \right)}_{feed} - {y\left( {H_{2}S} \right)}_{treat}}{{y\left( {H_{2}S} \right)}_{feed}}}{\frac{\left. {{y\left( {CO}_{2} \right)}_{feed} - {y\left( {CO}_{2} \right)}} \right)_{treat}}{\left. {y\left( {CO}_{2} \right)} \right)_{feed}}}$in which y(H₂S)_(feed) is the molar proportion (mol/mol) of H₂S in thestarting fluid, y(H₂S)_(treat) is the molar proportion in the treatedfluid, y(CO₂)_(feed) is the molar proportion of CO₂ in the startingfluid and y(CO₂)_(treat) is the molar proportion of CO₂ in the treatedfluid.

In preferred embodiments, the fluid stream is a fluid stream comprisinghydrocarbons, especially a natural gas stream. More preferably, thefluid stream comprises more than 1.0% by volume of hydrocarbons, evenmore preferably more than 5.0% by volume of hydrocarbons, mostpreferably more than 15% by volume of hydrocarbons.

The partial hydrogen sulfide pressure in the fluid stream is typicallyat least 2.5 mbar. In preferred embodiments, a partial hydrogen sulfidepressure of at least 0.1 bar, especially at least 1 bar, and a partialcarbon dioxide pressure of at least 0.2 bar, especially at least 1 bar,is present in the fluid stream. More preferably, a partial hydrogensulfide pressure of at least 0.1 bar and a partial carbon dioxidepressure of at least 1 bar is present in the fluid stream. Mostpreferably, a partial hydrogen sulfide pressure of at least 0.5 bar anda partial carbon dioxide pressure of at least 1 bar is present in thefluid stream. The partial pressures stated are based on the fluid streamon first contact with the absorbent in the absorption step.

In preferred embodiments, a total pressure of at least 3.0 bar, morepreferably at least 5.0 bar, even more preferably at least 20 bar, ispresent in the fluid stream. In preferred embodiments, a total pressureof at most 180 bar is present in the fluid stream. The total pressure isbased on the fluid stream on first contact with the absorbent in theabsorption step.

In the process according to the invention, the fluid stream is contactedwith the absorbent in an absorption step in an absorber, as a result ofwhich carbon dioxide and hydrogen sulfide are at least partly scrubbedout. This gives a CO₂- and H₂S-depleted fluid stream and a CO₂- andH₂S-laden absorbent.

The absorber used is a scrubbing apparatus used in customary gasscrubbing processes. Suitable scrubbing apparatuses are, for example,random packings, columns having structured packings and having trays,membrane contactors, radial flow scrubbers, jet scrubbers, Venturiscrubbers and rotary spray scrubbers, preferably columns havingstructured packing, having random packings and having trays, morepreferably columns having trays and having random packings. The fluidstream is preferably treated with the absorbent in a column incountercurrent. The fluid is generally fed into the lower region and theabsorbent into the upper region of the column. Installed in tray columnsare sieve trays, bubble-cap trays or valve trays, over which the liquidflows. Columns having random packings can be filled with differentshaped bodies. Heat and mass transfer are improved by the increase inthe surface area caused by the shaped bodies, which are usually about 25to 80 mm in size. Known examples are the Raschig ring (a hollowcylinder), Pall ring, Hiflow ring, Intalox saddle and the like. Therandom packings can be introduced into the column in an ordered manner,or else randomly (as a bed). Possible materials include glass, ceramic,metal and plastics. Structured packings are a further development ofordered random packings. They have a regular structure. As a result, itis possible in the case of structured packings to reduce pressure dropsin the gas flow. There are various designs of structured packings, forexample woven packings or sheet metal packings. Materials used may bemetal, plastic, glass and ceramic.

The temperature of the absorption medium in the absorption step isgenerally about 30 to 100° C., and when a column is used is, forexample, 30 to 70° C. at the top of the column and 50 to 100° C. at thebottom of the column.

The process according to the invention may comprise one or more,especially two, successive absorption steps. The absorption can beconducted in a plurality of successive component steps, in which casethe crude gas comprising the acidic gas constituents is contacted with asubstream of the absorbent in each of the component steps. The absorbentwith which the crude gas is contacted may already be partly laden withacidic gases, meaning that it may, for example, be an absorbent whichhas been recycled from a downstream absorption step into the firstabsorption step, or be partly regenerated absorbent. With regard to theperformance of the two-stage absorption, reference is made topublications EP 0 159 495, EP 0 190 434, EP 0 359 991 and WO 00100271.

The process according to the invention may comprise one or more,especially two, successive absorption steps. The absorption can beconducted in a plurality of successive component steps, in which casethe crude gas comprising the acidic gas constituents is contacted with asubstream of the absorbent in each of the component steps. The absorbentwith which the crude gas is contacted may already be partly laden withacidic gases, meaning that it may, for example, be an absorbent whichhas been recycled from a downstream absorption step into the firstabsorption step, or be partly regenerated absorbent. With regard to theperformance of the two-stage absorption, reference is made topublications EP 0 159 495, EP 0 190 434, EP 0 359 991 and WO 00100271.

The process preferably comprises a regeneration step in which the CO₂-and H₂S-laden absorbent is regenerated. In the regeneration step, CO₂and H₂S and optionally further acidic gas constituents are released fromthe CO₂- and H₂S-laden absorbent to obtain a regenerated absorbent.Preferably, the regenerated absorbent is subsequently recycled into theabsorption step. In general, the regeneration step comprises at leastone of the measures of heating, decompressing and stripping with aninert fluid.

The regeneration step preferably comprises heating of the absorbentladen with the acidic gas constituents, for example by means of aboiler, natural circulation evaporator, forced circulation evaporator orforced circulation flash evaporator. The absorbed acid gases arestripped out by means of the steam obtained by heating the solution.Rather than steam, it is also possible to use an inert fluid such asnitrogen. The absolute pressure in the desorber is normally 0.1 to 3.5bar, preferably 1.0 to 2.5 bar. The temperature is normally 50° C. to170° C., preferably 80° C. to 130° C., the temperature of course beingdependent on the pressure.

The regeneration step may alternatively or additionally comprise adecompression. This includes at least one decompression of the ladenabsorbent from a high pressure as exists in the conduction of theabsorption step to a lower pressure. The decompression can beaccomplished, for example, by means of a throttle valve and/or adecompression turbine. Regeneration with a decompression stage isdescribed, for example, in publications U.S. Pat. Nos. 4,537,753 and4,553,984.

The acidic gas constituents can be released in the regeneration step,for example, in a decompression column, for example a flash vesselinstalled vertically or horizontally, or a countercurrent column withinternals.

The regeneration column may likewise be a column having random packings,having structured packings or having trays. The regeneration column, atthe bottom, has a heater, for example a forced circulation evaporatorwith circulation pump. At the top, the regeneration column has an outletfor the acid gases released. Entrained absorption medium vapors arecondensed in a condenser and recirculated to the column.

It is possible to connect a plurality of decompression columns inseries, in which regeneration is effected at different pressures. Forexample, regeneration can be effected in a preliminary decompressioncolumn at a high pressure typically about 1.5 bar above the partialpressure of the acidic gas constituents in the absorption step, and in amain decompression column at a low pressure, for example 1 to 2 barabsolute. Regeneration with two or more decompression stages isdescribed in publications U.S. Pat. Nos. 4,537,753, 4,553,984, EP 0 159495, EP 0 202 600, EP 0 190 434 and EP 0 121 109.

Because of the optimal matching of the content of the amine componentsand of the acid, the inventive absorbent has a high loading capacitywith acidic gases, which can also be desorbed again easily. In this way,it is possible to significantly reduce energy consumption and solventcirculation in the process according to the invention.

For a minimum energy requirement in the regeneration of the absorbent,it is advantageous when there is a maximum difference between the pH atthe temperature of the absorption and the pH at the temperature of thedesorption, since this facilitates the separation of the acid gases fromthe absorbent.

The invention is illustrated in detail by the appended drawing and theexample which follows.

FIG. 1 is a schematic diagram of a plant suitable for performing theprocess according to the invention.

According to FIG. 1, via the inlet Z, a suitably pretreated gascomprising hydrogen sulfide and carbon dioxide is contacted incountercurrent, in an absorber A1, with regenerated absorbent which isfed in via the absorbent line 1.01. The absorbent removes hydrogensulfide and carbon dioxide from the gas by absorption; this affords ahydrogen sulfide- and carbon dioxide-depleted clean gas via the offgasline 1.02.

Via the absorbent line 1.03, the heat exchanger 1.04 in which the CO₂-and H₂S-laden absorbent is heated up with the heat from the regeneratedabsorbent conducted through the absorbent line 1.05, and the absorbentline 1.06, the CO₂- and H₂S-laden absorbent is fed to the desorptioncolumn D and regenerated.

Between the absorber A1 and heat exchanger 1.04, a flash vessel may beprovided (not shown in FIG. 1), in which the CO₂- and H₂S-ladenabsorbent is decompressed to, for example, 3 to 15 bar.

From the lower part of the desorption column D, the absorbent isconducted into the boiler 1.07, where it is heated. The mainlywater-containing vapor is recycled into the desorption column D, whilethe regenerated absorbent is fed back to the absorber A1 via theabsorbent line 1.05, the heat exchanger 1.04 in which the regeneratedabsorbent heats up the CO₂- and H₂S-laden absorbent and at the same timecools down itself, the absorbent line 1.08, the cooler 1.09 and theabsorbent line 1.01. Instead of the boiler shown, it is also possible touse other heat exchanger types to generate the stripping vapor, such asa natural circulation evaporator, forced circulation evaporator orforced circulation flash evaporator. In the case of these evaporatortypes, a mixed-phase stream of regenerated absorbent and stripping vaporis returned to the bottom of the desorption column, where the phaseseparation between the vapor and the absorbent takes place. Theregenerated absorbent to the heat exchanger 1.04 is either drawn offfrom the circulation stream from the bottom of the desorption column tothe evaporator or conducted via a separate line directly from the bottomof the desorption column to the heat exchanger 1.04.

The CO₂- and H₂S-containing gas released in the desorption column Dleaves the desorption column D via the offgas line 1.10. It is conductedinto a condenser with integrated phase separation 1.11, where it isseparated from entrained absorbent vapor. In this and all the otherplants suitable for performance of the process according to theinvention, condenser and phase separation may also be present separatelyfrom one another. Subsequently, a liquid consisting mainly of water isconducted through the absorbent line 1.12 into the upper region of thedesorption column D, and a CO₂- and H₂S-containing gas is discharged viathe gas line 1.13.

EXAMPLES

In the examples, the following abbreviations are used:

MDEA: methyldiethanolamine

TBAEE: 2-(2-tert-butylaminoethoxy)ethanol

Example 1

The temperature dependence of the pH of aqueous amine solutions orpartly neutralized amine solutions was determined in the temperaturerange from 20° C. to 120° C. A pressure apparatus was used, in which thepH can be measured up to 120° C.

The table which follows reports the pH (50° C.), the pH (120° C.) andthe difference pH(50° C.)-pH(120° C.).

DN*** pH pH pH (50° C.) − Ex. Composition b/a** [%] (50° C.) (120° C.)pH (120° C.) 1-1* 40% MDEA — — 11.01 9.58 1.43 1-2* 40% MDEA + 0.5%H₃PO₄ — 5.02 9.76 8.29 1.47 1-3 40% MDEA + 6.2% TBAEE + 0.118% H₂SO₄0.11 0.64 10.87 9.2 1.67 1-4 40% MDEA + 6.2% TBAEE + 1.89% H₂SO₄ 0.1110.30 9.45 7.9 1.55 1-5 30% MDEA + 15% TBAEE + 0.3% H₂SO₄ 0.37 1.7710.57 8.83 1.74 1-6 30% MDEA + 15% TBAEE + 0.6% H₂SO₄ 0.37 3.55 10.218.4 1.81 1-7 30% MDEA + 15% TBAEE + 0.8% H₂SO₄ 0.37 4.73 9.89 8.16 1.731-8 30% MDEA + 15% TBAEE + 1.2% H₂SO₄ 0.37 7.10 9.79 8.13 1.66 1-9 30%MDEA + 15% TBAEE + 1.6% H₂SO₄ 0.37 9.46 9.77 7.9 1.87 1-10 30% MDEA +15% TBAEE + 0.3% H₃PO₄ 0.37 2.66 10.56 8.81 1.75 1-11 30% MDEA + 15%TBAEE + 0.8% H₃PO₄ 0.37 7.10 10.21 8.49 1.72 1-12 30% MDEA + 15% TBAEE +1.6% H₃PO₄ 0.37 14.21 9.82 8.06 1.76 *comparative example **molar ratioof b/a ***degree of neutralization (based on TBAEE + MDEA)

It is clear that there is a greater difference between the pH values at50° C. and 120° C. in the inventive examples. Since the absorption iseffected in the region of 50° C. and desorption or regeneration in theregion of 120° C., the greater pH differential is a pointer to anenergetically improved regeneration.

Example 2

In a pilot plant, the CO₂ absorption and the heating energy introducedin the course of regeneration for a defined H₂S concentration of thecleaned gas were examined for aqueous absorbents.

The pilot plant corresponded to FIG. 1. In the absorber, a structuredpacking was used. The pressure was 60 bar. The packing height in theabsorber was 3.2 m with a column diameter of 0.0531 m. In the desorber,a structured packing was used. The pressure was 1.8 bar. The packingheight in the desorber was 6.0 m with a diameter of 0.085 m.

A gas mixture of 93% by volume of N₂, 5% by volume of CO₂ and 2% byvolume of H₂S was conducted into the absorber at a mass flow rate of 47kg/h and a temperature of 40° C. In the absorber, the absorbentcirculation rate was 60 kg/h. The temperature of the absorbent was 50°C. The regeneration energy was adjusted such that an H₂S concentrationof 5 ppm was attained in the cleaned gas.

The following table shows the results of these experiments:

y(CO₂) at Relative absorber regeneration outlet energy** Ex. Aqueouscomposition [% by vol.] [%] 2-1* 40% MDEA 1.87 100.0 2-2* 40% MDEA +0.5% H₃PO₄ 1.89 73.3 2-3* 30% MDEA + 15% TBAEE 0.91 91.6 2-4 30% MDEA +15% TBAEE + 0.8% 0.99 57.8 H₃PO₄ 2-5* 30% MDEA + 15% TBAEE + 1.6% 1.1556.9 H₃PO₄ 2-6 30% MDEA + 15% TBAEE + 0.6% 1.54 65.1 H₂SO₄ 2-7 30%MDEA + 15% TBAEE + 0.8% 1.47 64.8 H₂SO₄ 2-8 30% MDEA + 15% TBAEE + 1.2%1.50 64.1 H₂SO₄ 2-9 30% MDEA + 15% TBAEE + 1.6% 1.55 62.2 H₂SO₄*comparative example **with regard to example 2-1*

In a comparison of comparative example 2-2* with examples 2-4 to 2-9, itis clear that the additional use of TBAEE brings about an increased CO₂absorption (lower CO₂ concentration y(CO₂) at the absorber outlet) forthe same H₂S absorption. At the same time, the heating energy introducedin the regeneration remains approximately the same or falls. Thecomparison of comparative example 2-3* with examples 2-6 to 2-9 showsthat the addition of acid significantly lowers the heating energyintroduced in the course of the regeneration. Since the H₂Sconcentration in the purified gas was always 5 ppm, the examples showhow varying the compositions within the limits according to theinvention permits the setting of a defined H₂S selectivity.

Example 3

The stability of various aqueous absorbents was investigated.

Aqueous solutions having an MDEA and TBAEE content in accordance withthe table below, and a loading in each case of 20 m³(STP)/t(absorbent)CO₂ and H₂S were held in a closed vessel at a temperature of 160° C. for125 hours. Subsequently the amount of undecomposed MDEA was determined,and the fraction of decomposed MDEA was calculated.

The results are listed in the table below.

MDEA [% by TBAEE DN** Decomposed Ex. wt.] [% by wt.] Acid [%] MDEA [%]3-1* 35.7 12.1 3.7% by wt. H₂SO₄ 20.1 20 3-2 35.7 12.1 2.0% by wt. H₂SO₄10.9 19 3-3 35.7 12.1 1.0% by wt. H₂SO₄ 5.4 14 3-4 35.7 12.1 0.5% by wt.H₂SO₄ 2.7 8 3-5* 35.7 12.1 — — 2.5 *comparative example **degree ofneutralization (based on TBAEE + MDEA).

It is evident that the presence of acid accelerates the decomposition ofMDEA The degree of decomposition is dependent on the amount of acid,which is why a relatively small amount of acid as in the compositionsaccording to the invention is advantageous.

The invention claimed is:
 1. A process for removing an acidic gas from afluid stream, said process comprising: contacting the fluid stream whichis selected from gases and which has a total pressure of at least 3.0bar, with an absorbent, comprising an aqueous solution comprising: a) atertiary amine; b) a sterically hindered secondary amine of the generalformula (I)

in which R₁ and R₂ are each independently selected from C₁₋₄-alkyl andC₁₋₄-hydroxyalkyl; R₃, R₄, R₅ and R₆ are each independently selectedfrom hydrogen, C₁₋₄-alkyl and C₁₋₄-hydroxyalkyl, with the proviso thatat least one R₄ and/or R₅ radical on the carbon atom bonded directly tothe nitrogen atom is C₁₋₄-alkyl or C₁₋₄-hydroxyalkyl when R₃ ishydrogen; x and y are integers from 2 to 4 and z is an integer from 1 to4; where the molar ratio of b) to a) is in the range from 0.3 to 0.7,and c) an acid in an amount, calculated as neutralization equivalentrelative to the protonatable nitrogen atoms in a) and h), of 1.0 to9.0%; wherein the acid is selected from the group consisting of amineral acid (excluding phosphoric acid and partial esters thereof), acarboxylic acid, a sulfonic acid, a tertiary aminocarboxylic acid, anN-sec-alkylaminocarboxylic acid and an N-tert-alkylamino-carboxylicacid, with the proviso that the acid does not comprise a phosphonicacid, and there is a partial hydrogen sulfide pressure of at least 0.1bar and/or a partial carbon dioxide pressure of at least 0.2 bar in thefluid stream.
 2. The process according to claim 1, wherein the fluidstream comprises a hydrocarbon.
 3. The process according to claim 1,wherein there is a partial hydrogen sulfide pressure of at least 0.1 barand a partial carbon dioxide pressure of at least 1.0 bar in the fluidstream.
 4. The process according to claim 1, wherein the laden absorbentis regenerated by a) heating, b) decompression, c) stripping with aninert fluid or a combination of two or all of these measures.